I am a senior editor at Forbes, covering legal affairs, corporate finance, macroeconomics and the occasional sailing story. I was the Southwest Bureau manager for Forbes in Houston from 1999 to 2003, when I returned home to Connecticut for a Knight fellowship at Yale Law School. Before that I worked for Bloomberg Business News in Houston and the late, great Dallas Times Herald and Houston Post. While I am a Chartered Financial Analyst and have a year of law school under my belt, most of what I know about financial journalism, I learned in Texas.

The Best Thing About Shale Gas: We Know Where It Is

The shale-gas revolution has been, like all revolutions, a mixed blessing. It has unleashed a flood of cheap energy on the nation, but it’s also created a treadmill for drillers who must keep pouring capital into wells in a potentially hopeless attempt to show growing earnings from producing gas.

Retired BHP Billiton Chief Charles “Chip” Goodyear sketched out this bleak scenario this afternoon at the Yale Alumni in Energy Conference, an annual gathering of alumni active in all sides of the energy industry. Far from becoming a vast new source of baseload electricity fuel or even exports as liquified natural gas, a lot of the shale gas will essentially serve as a reserve in times of shortage, he said.

“We have a huge luxury we didn’t have before,” he said. “We know where the hydrocarbon is, and we know how much it costs to get out of the ground.”

Goodyear has plenty of experience with the economics of oil and gas extraction. A Yale and Wharton grad, he worked his way up at BHP Billiton from 1999 to 2007 as the Australian mining and energy company expanded from a market cap of $12 billion to $220 billion. He now runs a private investment firm and sits on the board of Anadarko Petroleum.

The combination of shale reserves and fracking technology has created vast new reserves that are fundamentally different than gas and oil pockets in the past, he said. Instead of hunting for them with expensive exploratory wells, drillers know exactly where the gas and oil are now, trapped in huge sandstone formations that extend across entire states.

The wells tend to generate 20% annual returns on capital invested, he said, but they also tend to decline at rates up to 80% in the first 18 months, meaning companies that want to show an increase in production must roll the cash flow into an expanding number of wells to stay ahead of the decline. That treadmill caught up with Chesapeake Energy, which spent billions on leases and drilling but ousted its colorful chief, Aubrey McClendon, earlier this year as it racked up a big losses and was forced to retrench.

“Chesapeake was a shell game, or maybe I should say a shale game,” Goodyear said. “I’m not sure it created any economic value at all.”

As gas production increases some are talking about — and fretting over — the possibility of exporting it as LNG to countries like Japan. But Goodyear said that assumes prices hold where they are on the international market, which is unlikely given huge new discoveries closer to Asia. Anadarko discovered a massive gas field off the coast of Mozambique in 2006 that extends across 100 miles and may contain 70 trillion cubic feet of gas (US yearly gas consumption: 30 tcf).

“I’ve never seen anything like it before,” Goodyear said of the field. “It looks essentially like somebody laid down a layer of snow that is 500-1000 feet deep.”

That supply will likely drive the price in Japan from $17 to $8 per million cubic feet even as that country ramps up imports to replace retiring nuclear electric plants. Bad news for the more than 20 U.S. LNG terminal projects on the drawing board that assume cheap shale gas can be exported into more lucrative markets. The transport cost across the Pacific is $5 per mcf, he said.

“You can see that new gas is not going baseload” generation, he said.

Unconventional oil reserves like the Bakken shale are similarly on the edge, with production costs for some requiring $110 per barrel Brent to make sense. In both cases the higher cost reserves will come into play only when prices rise sharply.

“They will be in the market time to time, but they won’t be in the market all the time,” he said.

Bad news for high-cost, highly leveraged drillers but good news for the U.S. economy overall. The certainty of new supply when prices rise will give confidence to manufacturers and consumers as they plan for the future, he said.

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unconventional oil reserves like the Bakken are also natural gas plays – some shales have liquids but all the shale plays have gas.

If the price of gas goes to $5, the Bakken becomes much more profitable re:less of where oil goes. You could easily see domestic drilling running full tilt with $5 gas and $60 oil, although the emphasis might switch back towards dryer plays.

The other point is the price of extraction still seems to be going down. The technology is becoming more sophisticated.

The Bakkens have associated gas but, in reality, the Bakken play is notoriously sparse in natural gas

The idea that newer technologies are increasing the production of natural gas plays from shale might be erroneous. As far as I can tell, production of individual ng plays has not increased since 2009, regardless of whether more sand, more laterals or more propellants are used.

What has changed is the time to completion of shale plays. Shales plays are drilled quicker but I don’t know if they are drilled more economically.

I foprgot to mention. the reason it is hard to increase productivity from shale and ng plays is that shale is an energy lightweight. Shale has the energy equivalent of a bag of popcorn. Similar to trying to get blood out of a turnip.